U.S. patent number 11,016,219 [Application Number 16/475,552] was granted by the patent office on 2021-05-25 for delta encoding of downhole images of petrophysical rock properties.
This patent grant is currently assigned to HALLIBURTON ENERGY SERVICES, INC.. The grantee listed for this patent is Halliburton Energy Services, Inc.. Invention is credited to Laban M. Marsh, Paul F. Rodney.
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United States Patent |
11,016,219 |
Marsh , et al. |
May 25, 2021 |
Delta encoding of downhole images of petrophysical rock
properties
Abstract
System and methods for encoding downhole image data are
provided. Measurements collected by a downhole tool around a
circumference of a borehole drilled within a formation are
obtained. The acquired measurements are assigned to a plurality of
azimuthal bins. Each azimuthal bin corresponds to an angular sector
around the circumference of the borehole in which at least one of
the measurements was collected by the downhole tool at a
predetermined depth within the formation. At least one of a
plurality of delta encoding schemes is selected for encoding the
measurements assigned to the plurality of azimuthal bins. A
delta-encoded binary representation of the measurements assigned to
the plurality of bins is generated, based on the selected delta
encoding scheme. The generated delta-encoded binary representation
is transmitted from the downhole computing device to a surface
computing device located at the surface of the borehole.
Inventors: |
Marsh; Laban M. (Houston,
TX), Rodney; Paul F. (Spring, TX) |
Applicant: |
Name |
City |
State |
Country |
Type |
Halliburton Energy Services, Inc. |
Houston |
TX |
US |
|
|
Assignee: |
HALLIBURTON ENERGY SERVICES,
INC. (Houston, TX)
|
Family
ID: |
63371017 |
Appl.
No.: |
16/475,552 |
Filed: |
March 1, 2017 |
PCT
Filed: |
March 01, 2017 |
PCT No.: |
PCT/US2017/020233 |
371(c)(1),(2),(4) Date: |
July 02, 2019 |
PCT
Pub. No.: |
WO2018/160176 |
PCT
Pub. Date: |
September 07, 2018 |
Prior Publication Data
|
|
|
|
Document
Identifier |
Publication Date |
|
US 20200241166 A1 |
Jul 30, 2020 |
|
Current U.S.
Class: |
1/1 |
Current CPC
Class: |
G06T
9/00 (20130101); E21B 47/20 (20200501); H04N
19/593 (20141101); E21B 47/024 (20130101); E21B
47/0025 (20200501); E21B 49/00 (20130101); G01V
11/002 (20130101); H04N 19/103 (20141101); G06T
9/004 (20130101) |
Current International
Class: |
E21B
47/024 (20060101); E21B 49/00 (20060101); G01V
11/00 (20060101); H04N 19/103 (20140101); E21B
47/002 (20120101); E21B 47/20 (20120101) |
Field of
Search: |
;175/45,50 ;324/388
;702/6,8-9,11 |
References Cited
[Referenced By]
U.S. Patent Documents
Other References
International Search Report and the Written Opinion, dated Jan. 2,
2018, PCT/US2017/020233, 9 pages, ISA/KR. cited by applicant .
Lamont-Doherty Earth Observatory--The Earth Institute at Columbia
University, "An Introduction to Logging While Drilling," Seminar in
Marine Geophysics, Feb. 14, 2008,
http://www.ldeo.columbia.edu/res/diy/mgg/lodos/Education/Logging/slides/L-
WD_Feb_15_2008.pdf. cited by applicant.
|
Primary Examiner: Aiello; Jeffrey P
Claims
What is claimed is:
1. A method of encoding downhole image data, the method comprising:
obtaining, by a telemetry device coupled to a drill string,
measurements collected by a downhole tool of the drill string for
different points around a circumference of a borehole being drilled
within a formation, the measurements including values of one or
more formation properties, and the downhole tool including one or
more positional sensors for tracking an azimuthal position of the
downhole tool within the borehole and a relative orientation of the
downhole tool at a current depth of the drill string within the
formation; storing, in a memory of the telemetry device, the
measurements obtained for each point around the circumference of
the borehole in association with a selected one of a plurality of
azimuthal bins, the selected azimuthal bin corresponding to the
azimuthal position of the downhole tool when the measurements for
that point were collected by the downhole tool at the current depth
of the drill string within the formation; analyzing, by a processor
of the telemetry device, the stored measurements to identify trend
characteristics of the one or more formation properties associated
with the plurality of azimuthal bins; selecting, by the processor
of the telemetry device, an optimal delta encoding scheme from
among a plurality of delta encoding schemes for delta encoding the
stored measurements according to an order of the plurality of
azimuthal bins that reduces a size of the measurements for faster
transmission to a surface of the borehole relative to other delta
encoding schemes in the plurality of delta encoding schemes, based
on the identified trend characteristics of the one or more
formation properties at the current depth and the relative
orientation of the downhole tool within the formation; generating,
by the processor of the telemetry device, a delta-encoded binary
representation of the stored measurements according to the selected
optimal delta encoding scheme; and transmitting, by a pulse
modulator of the telemetry device, the generated delta-encoded
binary representation from the downhole tool to a computing device
located at the surface of the borehole.
2. The method of claim 1, wherein the pulse modulator of the
telemetry device is integrated within a bottom-hole assembly of the
drill string disposed within the borehole.
3. The method of claim 2, wherein the telemetry device and the
downhole tool are components within a housing of the bottom hole
assembly of the drill string.
4. The method of claim 1, wherein the one or more positional
sensors include an angle sensor incorporated within the downhole
tool.
5. The method of claim 4, wherein the angle sensor is an
accelerometer or a magnetometer.
6. The method of claim 1, wherein the downhole tool is at least one
of a logging-while-drilling (LWD) tool or a
measurement-while-drilling (MWD) tool coupled to the drill
string.
7. The method of claim 6, wherein the values of the one or more
formation properties included in the measurements collected by the
downhole tool at each of the different points around the
circumference of the borehole represent an image of a section of
the borehole at the current depth of the downhole tool within the
formation.
8. The method of claim 1, wherein analyzing trend characteristics
includes identifying a symmetry point corresponding to at least one
of the plurality of azimuthal bins.
9. The method of claim 8, wherein identifying the symmetry point
comprises: performing a linear regression of the stored
measurements by fitting the values of the one or more formation
properties to a sine wave having an amplitude and a phase offset;
and identifying the symmetry point based on the phase offset of the
fitted sine wave.
10. The method of claim 1, wherein the measurements collected by
the downhole tool for points around different portions of the
circumference of the borehole are indicative of different layers of
the formation at the current depth of the drill string.
11. A system for encoding downhole image data, the system
comprising: a pulse modulator; at least one processor coupled to
the pulse modulator; and a memory coupled to the at least one
processor, the memory having instructions stored therein, which
when executed by the at least one processor, cause the at least one
processor to perform a plurality of functions, including functions
to: obtain measurements collected by a downhole tool of a drill
string for different points around a circumference of a borehole
being drilled within a formation, the measurements including values
of one or more formation properties, and the downhole tool
including one or more positional sensors for tracking an azimuthal
position of the downhole tool within the borehole and a relative
orientation of the downhole tool at a current depth of the drill
string within the formation; store, in the memory, the measurements
obtained for each point around the circumference of the borehole in
association with a selected one of a plurality of azimuthal bins,
the selected azimuthal bin corresponding to the azimuthal position
of the downhole tool when the measurements for that point were
collected by the downhole tool at the current depth of the drill
string within the formation; analyze the stored measurements to
identify trend characteristics of the one or more formation
properties associated with the plurality of azimuthal bins; select
an optimal delta encoding scheme from among a plurality of delta
encoding schemes for delta encoding the stored measurements
according to an order of the plurality of azimuthal bins that
reduces a size of the measurements for faster transmission to a
surface of the borehole relative to other delta encoding schemes in
the plurality of delta encoding schemes, based on the identified
trend characteristics of the one or more formation properties at
the current depth and the relative orientation of the downhole tool
within the formation; generate a delta-encoded binary
representation of the measurements according to the selected
optimal delta encoding scheme; and transmit, using the pulse
modulator, the generated delta-encoded binary representation from
the downhole tool to a computing device located at the surface of
the borehole.
12. The system of claim 11, wherein the delta-encoded binary
representation of the measurements is generated using a data
encoder integrated within a bottom-hole assembly of the drill
string disposed within the borehole.
13. The system of claim 12, wherein the data encoder and the
downhole tool are components of the bottom hole assembly of the
drill string.
14. The system of claim 11, wherein the one or more positional
sensors include an angle sensor incorporated within the downhole
tool.
15. The system of claim 14, wherein the angle sensor is an
accelerometer or a magnetometer.
16. The system of claim 11, wherein the values of the one or more
formation properties included in the measurements collected by the
downhole tool at each of the different points around the
circumference of the borehole represent an image of a section of
the borehole at the current depth of the downhole tool within the
formation.
17. The system of claim 11, wherein the functions performed by the
at least one processor further include functions to identify a
symmetry point corresponding to at least one of the plurality of
azimuthal bins.
18. The system of claim 17, wherein the functions performed by the
processor further include functions to: perform a linear regression
of the stored measurements by fitting the values of the one or more
formation properties to a sine wave having an amplitude and a phase
offset; and identify the symmetry point based on the phase offset
of the fitted sine wave.
19. The system of claim 11, wherein the measurements collected by
the downhole tool for points around different portions of the
circumference of the borehole are indicative of different layers of
the formation at the current depth of the drill string.
20. A non-transitory computer-readable storage medium having
instructions stored therein, which when executed by a computer
cause the computer to perform a plurality of functions, including
functions to: obtain measurements collected by a downhole tool of a
drill string for different points around a circumference of a
borehole being drilled within a formation, the measurements
including values of one or more formation properties, and the
downhole tool including one or more positional sensors for tracking
an azimuthal position of the downhole tool within the borehole and
a relative orientation of the downhole tool at a current depth of
the drill string within the formation; store, in a memory, the
measurements obtained for each point around the circumference of
the borehole in association with a selected one of a plurality of
azimuthal bins, the selected azimuthal bin corresponding to the
azimuthal position of the downhole tool when the measurements for
that point were collected by the downhole tool at the current depth
of the drill string within the formation; analyze the stored
measurements to identify trend characteristics of the one or more
formation properties associated with the plurality of azimuthal
bins; select an optimal delta encoding scheme from among a
plurality of delta encoding schemes for delta encoding, the stored
measurements according to an order of the plurality of azimuthal
bins that reduces a size of the measurements for faster
transmission to a surface of the borehole relative to other delta
encoding schemes in the plurality of delta encoding schemes, based
on the identified trend characteristics of the one or more
formation properties at the current depth and the relative
orientation of the downhole tool within the formation; generate a
delta-encoded binary representation of the measurements according
to the selected optimal delta encoding scheme; and transmit, using
mud pulse telemetry, the generated delta-encoded binary
representation from the downhole tool to a computing device located
at the surface of the borehole.
Description
CROSS-REFERENCE TO RELATED APPLICATION
The present application is a U.S. National Stage patent application
of International Patent Application No. PCT/US2017/020233, filed on
Mar. 1, 2017, the benefit of which is claimed and the disclosure of
which is incorporated herein by reference in its entirety.
FIELD OF THE DISCLOSURE
The present disclosure relates generally to electronic transmission
of downhole data during drilling operations, and more particularly,
to data compression techniques for electronic transmission of
downhole data during drilling operations.
BACKGROUND
When drilling an oil and gas well, it is often desirable to use
"logging-while-drilling" (LWD) or "measurement-while-drilling"
(MWD) sensors in the drill string to gather information downhole
while the well is being drilled. Such information may include
measurements of subsurface formation characteristics collected by
the sensors as the borehole is drilled, along with data relating to
the size and configuration of the borehole itself. Data from around
the borehole can also be used to produce an image log that provides
a drilling operator with an "image" of the circumference of the
borehole with respect to one or more formation characteristics.
While drilling is in progress, the LWD/MWD sensors in the drill
string may continuously or intermittently transmit the information
gathered downhole to a surface detector or data processing device
by some form of telemetry. For example, in mud pulse telemetry,
downhole data is transmitted in the form of pressure pulses that
propagate through the drilling fluid to the surface, where they are
detected by various types of transducers. However, due to data
bandwidth and downhole storage limitations in LWD/MWD systems, it
may not be possible to send all of the information gathered
downhole to the surface. For example, in cases where the data
acquisition rate by a downhole device is greater than the effective
transmission rate, only a fraction of the data collected by the
downhole sensors may get sent to the surface.
Data compression techniques may be utilized to reduce the size of
the downhole data before it gets sent to the surface and thereby
increase the effective data transmission rate. However, the amount
of data size reduction offered by conventional data compression
techniques may not be enough to sufficiently increase the effective
transmission rate without unduly sacrificing data quality.
BRIEF DESCRIPTION OF THE DRAWINGS
FIG. 1 is a diagram of an illustrative drilling system including a
drilling platform operating a downhole drilling assembly.
FIG. 2 is a block diagram of an illustrative telemetry device for
the downhole drilling assembly of FIG. 1.
FIG. 3 is an illustrative graph of drilling fluid pressure as a
function of time with multiple intervals between pressure
pulses.
FIG. 4 is another illustrative graph of drilling fluid pressure as
a function of time, in which a single interval of a first pulse is
followed by several possible second pulses.
FIG. 5 is a cross-sectional view of an illustrative borehole in
which a downhole tool rotates and collects measurements at its
current depth within the borehole.
FIG. 6 is a diagram of an illustrative process for "unwrapping" a
borehole image into a plurality of azimuthal bins for which delta
values may be calculated.
FIG. 7 is an illustrative plot of the measurements/image data
collected by the downhole tool relative to an azimuth of the tool
within the borehole.
FIGS. 8A, 8B and 8C are diagrams of various delta encoding patterns
for generating a delta-encoded binned representation of the
measurements collected by the downhole tool for a section of the
borehole.
FIG. 9 is a flow chart of an illustrative process of adaptively
encoding borehole image data according to an optimal delta encoding
scheme selected for the data.
FIG. 10 is a block diagram of an illustrative computer system in
which embodiments of the present disclosure may be implemented.
DESCRIPTION OF ILLUSTRATIVE EMBODIMENTS
Embodiments of the present disclosure relate to adaptively encoding
borehole image data according to an optimal delta encoding scheme
selected for the particular data being encoded. While the present
disclosure is described herein with reference to illustrative
embodiments for particular applications, it should be understood
that embodiments are not limited thereto. Other embodiments are
possible, and modifications can be made to the embodiments within
the spirit and scope of the teachings herein and additional fields
in which the embodiments would be of significant utility.
In the detailed description herein, references to "one embodiment,"
"an embodiment," "an example embodiment," etc., indicate that the
embodiment described may include a particular feature, structure,
or characteristic, but every embodiment may not necessarily include
the particular feature, structure, or characteristic. Moreover,
such phrases are not necessarily referring to the same embodiment.
Further, when a particular feature, structure, or characteristic is
described in connection with an embodiment, it is submitted that it
is within the knowledge of one skilled in the art to implement such
feature, structure, or characteristic in connection with other
embodiments whether or not explicitly described. It would also be
apparent to one skilled in the relevant art that the embodiments,
as described herein, can be implemented in many different
embodiments of software, hardware, firmware, and/or the entities
illustrated in the figures. Any actual software code with the
specialized control of hardware to implement embodiments is not
limiting of the detailed description. Thus, the operational
behavior of embodiments will be described with the understanding
that modifications and variations of the embodiments are possible,
given the level of detail presented herein.
The disclosure may repeat reference numerals and/or letters in the
various examples or Figures. This repetition is for the purpose of
simplicity and clarity and does not in itself dictate a
relationship between the various embodiments and/or configurations
discussed. Further, spatially relative terms, such as beneath,
below, lower, above, upper, uphole, downhole, upstream, downstream,
and the like, may be used herein for ease of description to
describe one element or feature's relationship to another
element(s) or feature(s) as illustrated, the upward direction being
toward the top of the corresponding figure and the downward
direction being toward the bottom of the corresponding figure, the
uphole direction being toward the surface of the wellbore, the
downhole direction being toward the toe of the wellbore. Unless
otherwise stated, the spatially relative terms are intended to
encompass different orientations of the apparatus in use or
operation in addition to the orientation depicted in the Figures.
For example, if an apparatus in the Figures is turned over,
elements described as being "below" or "beneath" other elements or
features would then be oriented "above" the other elements or
features. Thus, the exemplary term "below" can encompass both an
orientation of above and below. The apparatus may be otherwise
oriented (rotated 90 degrees or at other orientations) and the
spatially relative descriptors used herein may likewise be
interpreted accordingly.
Also, while a Figure may depict a horizontal wellbore or a vertical
wellbore, unless indicated otherwise, it should be understood by
those skilled in the art that the apparatus according to the
present disclosure is equally well suited for use in wellbores
having other orientations including vertical wellbores, slanted
wellbores, multilateral wellbores or the like. Likewise, unless
otherwise noted, even though a Figure may depict an onshore
operation, it should be understood by those skilled in the art that
the apparatus according to the present disclosure is equally well
suited for use in offshore operations. Further, unless otherwise
noted, even though a Figure may depict a cased hole, it should be
understood by those skilled in the art that the apparatus according
to the present disclosure is equally well suited for use in open
hole operations.
Illustrative embodiments and related methodologies of the present
disclosure will be described below in reference to FIGS. 1-10 as
they might be employed, for example, in a downhole device for
encoding and transmitting downhole data to the surface during a
drilling operation. The downhole device may be, for example, a data
encoder integrated within a telemetry unit or a bus controller of a
bottom hole assembly (BHA) located at the end of a drill string
disposed within a borehole being drilled through a subsurface
formation. Such a device may be communicatively coupled to a
"logging-while-drilling" (LWD) or "measurement-while-drilling"
(MWD) tool for acquiring formation property measurements collected
by the LWD/MWD tool over the course of the drilling operation. The
LWD/MWD downhole tool may be used to measure formation properties
at different depths within the formation as the borehole is
drilled. Such measurements may be collected by the downhole tool
around a section of the borehole to obtain an "image" of the
borehole section with respect to one or more formation
characteristics at a current depth of the downhole tool. In one or
more embodiments, such image data may be collected as the tool
rotates within the borehole and binned into a plurality of
azimuthal bins according to the azimuthal direction in which the
tool was positioned when the data was acquired. For example, image
data may be collected as a set of measured pairs including a
formation property measurement and a corresponding angle or
azimuthal position of the tool around the circumference of the
borehole relative to a predetermined reference point.
As will be described in further detail below, embodiments of the
present disclosure may be used to adaptively encode the binned
image data acquired from the LWD/MWD tool according to an optimal
delta encoding scheme. The optimal delta encoding scheme may be
used to minimize the size of the encoded data without sacrificing
the quality of the data or image being transmitted. Additional
features and advantages of the disclosed embodiments will be or
will become apparent to one of ordinary skill in the art upon
examination of the following figures and detailed description. It
is intended that all such additional features and advantages be
included within the scope of the disclosed embodiments. Further,
the illustrated figures are only exemplary and are not intended to
assert or imply any limitation with regard to the environment,
architecture, design, or process in which different embodiments may
be implemented.
FIG. 1 is a diagram of an illustrative drilling system 100 for
conducting a drilling operation at a well site. As shown in FIG. 1,
system 100 includes a drilling platform 102 located at the surface
of a wellbore or borehole 126. Borehole 126 is drilled into
different layers of a subsurface rock formation using a drill
string 108 that includes a string of drill pipes connected together
by "tool" joints 107. Drilling platform 102 is equipped with a
derrick 104 that supports a hoist 106. Hoist 106 suspends a top
drive 110 that is used to lower drill string 108 through a wellhead
112 and rotate drill string 108 within borehole 126. Connected to
the lower portion of drill string 108 is a bottom hole assembly
(BHA), which includes a drill bit 114, one or more downhole tools
132a and 132b (collectively referred to herein as "downhole tools
132a-b"), and a telemetry device 134. It should be appreciated that
drill bit 114, downhole tools 132a-b and telemetry device 134 may
be implemented, for example, as separate components within a
housing of the BHA at the end of drill string 108. Although not
shown in FIG. 1, it should also be appreciated that the BHA may
include additional components for supporting various functions
related to the drilling operations being conducted. Examples of
such components include, but are not limited to, drill collars,
stabilizers, reamers, and hole-openers.
Drilling of borehole 126 occurs as drill bit 114 penetrates the
subsurface formation while rotating at the end of drill string 108.
Drill bit 114 may be rotated in conjunction with the rotation of
drill string 108 by top drive 110. Additionally or alternatively,
drill bit 114 may be rotated independently from the rest of drill
string 108 by a downhole motor (not shown) positioned near drill
bit 114. Borehole 126 may be drilled in a vertical direction
through the formation or in a non-vertical direction, e.g., at
angles approaching or at horizontal. A borehole that is drilled at
an angle other than vertical is generally referred to as being
deviated. Drilling fluid may be pumped by a mud pump 116 through a
flow line 118, a stand pipe 120, a goose neck 124, top drive 110,
and down through drill string 108 at high pressures and volumes to
emerge through nozzles or jets in drill bit 114. The drilling fluid
emerging from drill bit 114 travels back up the borehole via a
channel or annulus formed between the exterior of drill string 108
and a borehole wall 128. The drilling fluid then goes through a
blowout preventer (not specifically shown) and into a mud pit 130
at the surface, where the fluid is cleaned and recirculated by mud
pump 116 through drill string 108 and borehole 126. The drilling
fluid may be used, for example, to cool drill bit 114, carry
cuttings from the base of the bore to the surface, balance the
hydrostatic pressure in the rock formations, or any of various
other purposes over the course of the drilling operation.
Drilling system 100 may employ, for example, mud pulse telemetry
for transmitting downhole information collected by downhole tool
132a and/or downhole tool 132b to the surface during the drilling
operation. However, it should be appreciated that embodiments are
not limited thereto and that any of various other types of data
communication techniques may be used for sending the downhole
information to the surface. Such techniques may include, for
example and without limitation, wireless communication techniques
and wireline or any other type of wired electrical communication
techniques. Downhole tool 132a may be, for example, an MWD tool for
measuring conditions downhole, including the movement, location,
and orientation of the drilling assembly contemporaneously with the
drilling of borehole 126. Downhole tool 132b may be, for example,
an LWD tool for measuring formation parameters around a
circumference of borehole 126. However, it should be appreciated
that the disclosed embodiments are not limited thereto and that
each of downhole tools 132a-b may be implemented using either an
MWD tool or an LWD tool. Also, it should be appreciated that while
distinctions between MWD and LWD may exist, the terms MWD and LWD
are often used interchangeably. For purposes of this disclosure, it
should be noted that the term "downhole tool" is used to refer to
both the collection of formation parameters and the collection of
information relating to the movement and position of the drilling
assembly.
In one or more embodiments, each of downhole tools 132a-b may
include a plurality of sensors for measuring formation parameters
and downhole conditions for different sections of borehole 126 as
it is drilled through the subsurface formation. For example,
downhole tools 132a may include a sensor for measuring the
azimuthal position of downhole tool 132a with respect to a fixed
direction, for example, magnetic north or gravitational high side
of borehole 126 (corresponding to the part of borehole 126 pointing
directly up towards the surface). Such a sensor may include, for
example, a system of magnetometers that sense the Earth's magnetic
field and reference the relative orientation of tool 132a with
respect to the magnetic field for purposes of tracking the tool's
azimuthal position. For example, if the magnetometer measures
cross-axial components of the Earth's magnetic field, the azimuthal
position of the tool around the circumference of borehole 126 may
be defined as: .phi.m=Tan.sup.-1(-By/Bx), where .phi.m is the
azimuthal position of the tool (which in this case may be referred
to as the magnetic high side angle) and Bx and By are cross-axial
components of the magnetic field. The cross-axial components of the
magnetic field in this example may be measured in a right-handed
coordinate system, where the reference for Bx is a vertical plane
passing through the point of measurement and tangent to the
borehole trajectory at the point of measurement.
Additionally or alternatively, the angle sensor may include, for
example, an accelerometer that senses the Earth's gravitational
pull and references the relative orientation of tool 132a with
respect to the gravitational high side in order to track the
orientation of tool 132a within the formation. As with the magnetic
high side angle, the gravitational high side angle around the
circumference of borehole 126 may be defined as:
.phi.g=Tan.sup.-1(-gy/gx), where .phi.g is the azimuthal position
of the tool (which in this case may be referred to as the
gravitational high side angle) and gx and gy are cross-axial
components of the gravitational field. The cross-axial components
of the gravitational field in this example may be measured in a
right-handed coordinate system, where the reference for gx is a
vertical plane passing through the point of measurement and tangent
to the borehole trajectory at the point of measurement. However, it
should be appreciated that embodiments of the present disclosure
are not limited thereto and that any of various other conventions
may be used for azimuthal reference angles. For purposes of
discussion and ease of explanation, the sensor for measuring
azimuthal angles with respect to a reference azimuthal angle will
be referred to herein as an "angle sensor," although many other
angles can be measured with an MWD or LWD tool (e.g., the
inclination or the azimuth of the borehole with respect to magnetic
North, which is the angle between the projection of the borehole
axis on a horizontal surface and the horizontal component of the
earth's magnetic field.) In some implementations, the angle sensor
may incorporate magnetometers, accelerometers, and/or other types
of angle sensors.
As will be described in further detail below, the data collected by
downhole tool 132a and/or 132b may include measurements of
formation properties around a circumference of the borehole at a
current depth of downhole tool 132a and/or 132b. In one or more
embodiments, the collected data may be transferred from downhole
tools 132a-b to telemetry device 134 for compressing or encoding
the data before it is transmitted to the surface. By compressing
the data prior to its transmission, it may be possible to reduce
the overall number of bits of information that need to be sent to
the surface relative to the same amount of uncompressed data, thus
increasing effective data transmission rate. In one or more
embodiments, telemetry device 134 may adaptively encode the data
using an optimal delta encoding scheme for reducing the size of the
data without sacrificing the quality of the data or resolution of
the borehole image being transmitted. As will be described in
further detail below, the optimal delta encoding scheme may be
selected from a plurality of available delta encoding schemes based
on the particular data being encoded or particular characteristics
of the formation in which the data was collected.
Telemetry device 134 may transmit the encoded data to the surface
by, for example, modulating the flow of drilling fluid through
drill string 108 so as to generate pressure pulses that propagate
to the surface. The pressure pulses may be received at the surface
by various transducers 136, 138 and 140, which convert the received
pulses into electrical signals for a signal digitizer 142 (e.g., an
analog to digital converter). While three transducers 136, 138 and
140 are shown in FIG. 1, a greater or fewer number of transducers
may be used as desired for a particular implementation. Digitizer
142 supplies a digital form of the pressure signals to a data
processing device or computer 144. Computer 144 may be implemented
using any type of computing device having at least one processor
and a memory. Computer 144 may process and decode the digital
signals received from digitizer 142 using an appropriate decoding
scheme. For example, the digital signals may be in the form of a
bit stream including reserved bits that indicate the particular
encoding scheme that was used to encode the data downhole. Computer
144 can use the reserved bits to identify the corresponding
decoding scheme to appropriately decode the data. The resulting
decoded telemetry data may be further analyzed and processed by
computer 144 to display useful information to a well site operator.
For example, a driller could employ computer system 144 to obtain
and monitor the position and orientation of the BHA (or one or more
of its components), other drilling parameters, and/or one or more
formation properties of interest over the course of the drilling
operation.
The pressure pulses transmitted by telemetry device 134 in the
above example may be, for example, traveling pressure signals that
are representative of measured downhole parameters. In an ideal
system, each and every pressure pulse created downhole would
propagate upstream and be easily detected by a transducer at the
surface. However, drilling fluid pressure generally tends to
fluctuate significantly and contain noise from several sources
(e.g., bit noise, torque noise, and mud pump noise). Bit noise may
be caused by, for example, the vibration of drill bit 114 during
the drilling operation. As the bit moves and vibrates, the drilling
fluid exit ports in the bit can be partially or momentarily
restricted, creating a high frequency noise in the pressure signal.
Also, torque noise may be generated downhole if drill string 108
starts to torque up as a result of drill bit 114 getting stuck
within a formation. The subsequent release of drill bit 114 would
relieve the torque on drill string 108 and generate a low
frequency, high amplitude pressure surge. Furthermore, mud pump 116
may create cyclic noise as the pistons within the pump force the
drilling fluid into the drill string.
Accordingly, drilling system 100 may include a dampener or desurger
152 to reduce noise. Flow line 118 couples to a drilling fluid
chamber 154 in desurger 152. A diaphragm or separation membrane 156
separates the drilling fluid chamber 154 from a gas chamber 158.
Desurger may include a gas chamber 158 filled with nitrogen at a
predetermined percentage, e.g., approximately 50% to 75% of the
operating pressure of the drilling fluid. The diaphragm 156 moves
with variations in the drilling fluid pressure, enabling the gas
chamber to expand and contract, thereby absorbing some of the
pressure fluctuations. While the desurger 152 absorbs some pressure
fluctuations, the desurger 152 and/or mud pump 116 also act as
reflective devices. That is, pressure pulses propagating from the
telemetry device 134 tend to reflect off the desurger 152 and/or
mud pump 116, sometimes a negative reflection, and propagate back
downhole. The reflections create interference that, in some cases,
adversely affects the ability to determine the presence of the
pressure pulses propagating from the telemetry device 134.
FIG. 2 is a block diagram of an illustrative configuration of
telemetry device 134 for drilling system 100 of FIG. 1, as
described above. As shown in FIG. 2, telemetry device 134 in this
example includes a data encoder 200 and a pulse modulator 202. In
some implementations, data encoder 200 and pulse modulator 202 may
be different components of a single physical device, e.g.,
different chips on a circuit board within telemetry device 134.
Alternatively, data encoder 200 and pulse modulator 202 may be
implemented as separate physical devices, e.g., separate circuit
boards that are communicatively coupled together via an electrical
or wired connection.
Data encoder 200 includes a processor 208 (e.g., a digital signal
processor (DSP)) and a memory 210 for processing sensor data 206
received from one or more downhole tools (e.g., downhole tools
132a-b of FIG. 1, as described above). The processor 208 operates
in accordance with software from memory 210 to represent the sensor
data 206 in the form of a digital transmit signal. In particular,
the software contained in memory 210 comprises multiple software
modules 212-218. Compression module 212 processes the incoming
sensor data to reduce the amount of transmitted data, such as by
various compression techniques, by eliminating particular data
points or by taking representative samples. In some cases, the data
stream may be differentially encoded, so that differences between
successive values are sent rather than the values themselves.
Usually, differential encoding permits a data stream to be
represented with fewer bits. Other compression techniques may be
equivalently used. Multiplexing and framing module 214 selects
sensor data from the various downhole tools to construct a single
transmit data stream. The transmit data stream is divided into data
blocks that may be accompanied by framing information in some
embodiments. The framing information may include synchronization
information and/or error correction information from forward error
correction (FEC) module 216. Channel coding module 218 converts the
digital transmit signal into a set of timings. The precise nature
of the set of timings depends on the particular pulse encoding
system, examples of which are discussed more below. The processor
208 then communicates the timings to the pulse modulator 202.
The pulse modulator 202 induces pressures pulses in the drilling
fluid within the drill string 108 based on the set of timings
received from the data encoder 200. The pulse modulator 202
includes a processor 220, a memory 222, an open solenoid 224, a
close solenoid 226, capacitor banks 227 and 228, and a battery 230.
The processor 220 operates in accordance with software from memory
222, in particular a pulse controller or control module 232, to
control creating pulses in the drilling fluid. The processor 220
accepts the set of timings from processor 208 of the data encoder
200 across communication pathway 234. The communication pathway 234
may be either a serial or parallel communication pathway. The pulse
controller 232 may, in bursts, receive sets of timings from the
data encoder 200 faster than sets of timings can be implemented.
Thus, memory 222 further comprises a buffer 236 in which the
processor 220 may place multiple sets of timings, the buffer 234
thereby acting as a queue.
The pulse modulator 202 creates pressure pulses in the drilling
fluid by control of a valve. In the embodiments illustrated the
valve (not specifically shown) is opened by operation of the open
solenoid 224, and the valve is closed by operation of the close
solenoid 226. Solenoids use relatively high amounts of current to
operate, in some cases more instantaneous current than battery 230
can provide. However, the power (voltage times current) used to
operate a solenoid is well within the capabilities of battery. To
address the current versus power issue, in accordance with at least
some embodiments each solenoid 224 and 226 is associated with a
capacitor bank 227 and 228, respectively. The battery 230 charges
each capacitor bank between uses at a charge rate within the
current capability of the battery 230. When the processor 220
commands the valve to open, capacitor bank 227 is electrically
coupled to the open solenoid 224, supplying electrical current at
sufficiently high rates to operate the solenoid (and open the
valve). Likewise, when the processor 220 commands the valve to
close, capacitor bank 228 is electrically coupled to the close
solenoid 226, supplying electrical current at sufficiently high
rates to operate the solenoid (and close the valve).
While the components of data encoder 200 in the above example,
including compression module 212, multiplexing and framing module
214, FEC module 216 and channel coding module 218, are described as
software modules, it should be appreciated that data encoder 200 is
not intended to be limited thereto and that the above-described
components of data encoder 200 may be implemented in hardware alone
or any combination of software, firmware, and hardware. Similarly,
while pulse controller 232 is described as a software module of
pulse modulator 202 in the above example, it should be appreciated
that pulse modulator 202 is not intended to be limited thereto and
that the pulse controller 232 of pulse modulator 202 may be
implemented in hardware alone or any combination of software,
firmware, and hardware.
In the above example, the valve that physically creates the
pressure pulses in the drilling fluid may take many forms. In some
cases, the valve may create pressure pulses by temporarily
restricting or even blocking flow of the drilling fluid in the
drill string. In situations where the drilling fluid is restricted
or blocked, an increase in drilling fluid pressure is created
(i.e., a positive-pulse system). In other cases, the valve may be
configured to divert a portion of the drilling fluid out of the
drill string into the annulus 126, thus bypassing the drill bit
114. In situations where the drilling fluid is diverted, a decrease
in drilling fluid pressure occurs (i.e., a negative-pulse system).
Either positive-pulse systems or negative-pulse systems may be used
in the various embodiments, so long as the telemetry device 134 can
create pressure transitions (lower drilling fluid pressure to
higher drilling fluid pressure, and vice versa) with sufficient
quickness (e.g., 18 milliseconds (ms)).
FIG. 3 shows an exemplary graph of downhole drilling fluid pressure
as a function of time. The drilling fluid pressure may be measured
at the surface by the computer system 144 coupled to one of the
transducers 136, 138 and/or 140 of drilling system 100 of FIG. 1,
as described above. The illustrative graph of FIG. 3 represents an
ideal situation where ideal square wave pulses are generated
downhole, and are detected as ideal square waves at the surface.
FIG. 3 shows the pulses as positive pulses for convenience, but
embodiments are not limited thereto and negative pulses may be used
instead. The duration of each pulse may be within a certain range
of time, e.g., from 80 milliseconds (ms) to 400 ms, depending on
the various parameters of the particular drilling system. In pure
pulse position modulations systems, the pulse durations are
substantially constant to aid in detection. However, in some
embodiments, a variety of pulse durations may be selectively used
(e.g., 50 ms pulses, 100 ms pulses, 150 ms pulses, and 200 ms
pulses).
The downhole data in this example may be transmitted in intervals.
FIG. 3 shows three such intervals I1, I2 and I3. In embodiments
utilizing pulse position modulation, an interval may be the amount
of time between coherent features of two consecutive pressure
pulses. For example, as shown in FIG. 3, an interval may be an
amount of time between leading pressure transitions of each pulse.
Alternatively, an interval may be the amount of time between
trailing pressure transitions of each pulse, or the amount of time
between the centers of each pulse. Each interval has a duration
that is at least a minimum time (MIN-TIME). An interval having
duration substantially equal to the MIN-TIME encodes a data value
zero. The MIN-TIME duration may allow the drilling fluid column to
settle after a pressure transition event (allows ringing and other
noise in the drilling fluid to dampen out). The MIN-TIME may change
for each particular drilling situation, but in most cases ranges
from between approximately 0.3 seconds to 2.0 seconds. In some
embodiments (e.g., positive-pulse systems), a MIN-TIME of 0.6
seconds may be used. In other embodiments (e.g., negative-pulse
systems) a MIN-TIME of 1.0 seconds may be used.
FIG. 4 shows a single interval comprising a first pulse 400 and
several possible second pulses (shown in dashed lines) to further
illustrate parameters. For purposes of pulse position modulation,
embodiments may utilize a window in which a pulse of an interval
may fall and yet still represent the same value. After the
MIN-TIME, a pulse may fall within one of several BIT-WIDTH windows.
So long as the pulse falls somewhere within one of the BIT-WIDTH
windows, the data value encoded is still the same. For example, the
pulse 402 falls within a first BIT-WIDTH window 404, and thus in
this particular example the interval encodes a data value zero
(e.g., hexadecimal 00). Pulse 406 falls within the next BIT-WIDTH
window, and therefore the time duration between pulse 400 and pulse
406 represents a first data value (e.g., hexadecimal 01). Likewise,
the pulse 408 falls within the third BIT-WIDTH window, and
therefore the time duration between pulse 400 and pulse 408 may
represent a second data value (e.g., hexadecimal 10). The data
value may be decoded using, for example, Equation (1) as follows:
DATA=(INTERVAL-MIN-TIME)/BIT-WIDTH (1), where DATA is the decoded
value, INTERVAL is the measured time between coherent features of
the two pulses, and MIN-TIME and BIT-WIDTH are as described above.
It should be noted that in the ideal case, DATA is an integer.
However, in the presence of noise, Equation (1) is likely to
produce a non-integer value. Accordingly, the value produced by
Equation (1) may be rounded (e.g., rounded up or down) to the
nearest integer. In some embodiments, a floor function for
truncation or a ceiling function for rounding up may also be used,
with different results in terms of error of the transmitted data
value. The BIT-WIDTH may change for each particular drilling
situation, but in most cases ranges from between approximately 20
ms to 120 ms, and in many cases a BIT-WIDTH of 40 ms is used. For a
particular number of bits encoded within each interval, there is a
maximum time (MAX-TIME) duration. For example, if a particular
interval encodes a four-bit number (which could therefore range
from zero to fifteen), the four-bit number at its maximum value
forces an interval duration equal to MAX-TIME.
The downhole data transmitted to the surface using the mud pulse
telemetry techniques described above may include encoded image data
based on measurements of formation properties collected by one or
more downhole tools, e.g., downhole tools 132a and/or 132b of FIG.
1, as described above. Also, as described above, the measurements
may be collected by the downhole tool(s) for a section of a
borehole (e.g., borehole 126 of FIG. 1) at a current depth of the
downhole tool(s) within the borehole. For example, the formation
property measurements may be collected by the downhole tool(s)
around the circumference of the borehole, as shown in the example
of FIG. 5.
FIG. 5 is a cross-sectional view of an illustrative borehole 500 in
which a downhole tool 510 rotates and collects measurements around
a circumference of the borehole. As shown in FIG. 5, downhole tool
510 may include a sensor 512 for measuring one or more formation
properties as tool 510 rotates in a clockwise or counterclockwise
direction within the borehole. Downhole tool 510 may be implemented
using, for example, downhole tool 132a or 132b of FIG. 1, as
described above. While only sensor 512 is shown in FIG. 5, it
should be appreciated that embodiments are not limited thereto and
that downhole tool 512 may include any number of sensors as desired
for a particular implementation.
In one or more embodiments, downhole tool 510 may also include
additional sensors (not shown) for measuring various drilling
parameters and/or conditions of borehole 500. In one example,
downhole tool 510 may further include a sensor for tracking the
tool's azimuthal position as it rotates around the circumference of
borehole 500. As described above, the angle sensor may include, for
example, one or more magnetometers or accelerometers for measuring
the orientation of tool 510 relative to the Earth's magnetic field
and/or gravitational field, respectively.
As will be described in further detail below, the measurements
collected by downhole tool 510 may be transformed into a
representation of the measured formation properties as measured
around the circumference of the borehole. The data can be
represented as, for example, an image log of one or more
representative formation characteristics at different points around
the circumference of borehole 500. An image of borehole 500 may
therefore represent a set of measurements around a section of
borehole 500 at the same measured depth, e.g., a current depth of
tool 510. Such image data may be collected by tool 510 as, for
example, a set of measured pairs including a formation property
measurement and a corresponding angle or azimuthal position of tool
510 around the circumference of borehole 500 when the measurement
was collected. The azimuthal position of tool 510 may correspond
to, for example, the azimuthal position of the particular sensor,
e.g., sensor 512, used to obtain the formation property
measurement.
In one or more embodiments, the formation property measurements
collected by tool 510 as it rotates within borehole 500 may be
binned into a plurality of azimuthal bins 502a-502h based on the
corresponding azimuthal position of tool 510 (and/or sensor 512).
As shown in FIG. 5, azimuthal bins 502a-502h may correspond to
different angular sectors around the circumference of borehole 500,
where the sectors may be of equal subtended angle based on the
number of sectors or corresponding bins used. For example, as eight
bins are used in FIG. 5, each of bins 502a-502h may correspond to
an angular sector of 45 degrees around borehole 500. Although eight
bins 502a-502h are shown in the example of FIG. 5, it should be
noted that embodiments are not intended to be limited thereto and
that any number of bins may be used. For example, the number of
bins may be four or any higher even number, e.g., 6, 8, 10, 12, 14,
16, etc., as desired for a particular implementation.
In one or more embodiments, the binned image data described above
may be transformed into a compressed binary representation using a
delta encoding compression technique prior to transmission to the
surface. Such a compression technique may include encoding a binned
image based on a set of delta values computed for the image data
bins. Each computed delta value may represent a difference between
a previously transmitted data value in a preceding bin and the data
value of the current bin. Each bin may include, for example, values
of one or more downhole formation parameters. Examples of such
parameters may include, but are not limited to, an uncompressed
electromagnetic wave resistivity (an eight-bit value encoded in two
intervals), an uncompressed gamma ray reading (an eight-bit value
encoded in two intervals), and an uncompressed density value (a
twelve bit value encoded in three intervals). Using the resistivity
parameter as an example, if the value of this parameter in a
current bin has not changed from the value that was previously
transmitted to the surface from a preceding bin, a delta value of
zero may be sent (rather than encoding again the entire eight bit
value). Likewise, if the resistivity parameter experiences any
change in value from the value previously sent, a number
representing the change in value may be transmitted to the
surface.
As only the change in value, or "delta" value, is sent to the
surface, the overall number of bits to transfer the information is
reduced, thereby increasing the effective data transfer rate to the
surface. The delta values may be encoded by quantizing the deltas
and using a reduced number of bits. The method used at present
transmits the image using a delta sequence of either 3 bits, 2
bits, or 1 bits. As will be described in further detail below,
embodiments of the present disclosure may be used to further reduce
the size of the delta encoded image by adaptively encoding the
binned image according to an optimal delta encoding scheme selected
for the particular image data.
FIG. 6 is a diagram illustrating how a borehole image may be
"unwrapped" into a plurality of bins from which a set of delta
values is computed for delta encoding the image. The borehole image
may constitute, for example, a set of formation property
measurements collected by a downhole tool, e.g., tool 510 of FIG.
5, as described above, as it rotates around a section 602 of a
borehole 600, as shown in FIG. 6. In contrast with FIG. 5, the
measurements collected by the downhole tool in this example may be
binned into a plurality of sixteen azimuthal bins 602a-602p.
However, it should be appreciated that any number of bins may be
used as desired for a particular implementation. It should also be
appreciated that, while the examples in FIGS. 5 and 6 show an even
number of azimuthal bins, the disclosed delta encoding techniques
are not intended to be limited thereto and that these techniques
may be applied using an odd number of azimuthal bins.
In one or more embodiments, the bins may be encoded in a sequential
order beginning at a first bin corresponding to a reference point
selected for the image relative to the face of the downhole tool
and then, processing subsequent bins in a predetermined direction
(e.g., clockwise) around the borehole. If the downhole tool is
positioned within a horizontal or deviated portion of the borehole,
the reference point may correspond to, for example, the bottom-most
portion of the borehole image when viewed relative to the
gravitational tool face downhole. However, if the downhole tool is
within a vertical or near-vertical portion of the borehole, a
reference point that is different from the bottom of the borehole
should be used. In such cases, the reference point of the image may
correspond to, for example, the magnetic tool face of the downhole
tool. For example, the delta values for the 16 azimuthal bins in
this example may be calculated as follows:
Bin 1 (uncompressed); Delta Bin 2=Bin 2-Bin 1; Delta Bin 3=Bin
3-Bin 2; Delta Bin 4=Bin 4-Bin 3; Delta Bin 5=Bin 5-Bin 4; . . .
Delta Bin 16=Bin 16-Bin 15; where Bins 1-16 correspond to bins
602a-602p of the unwrapped borehole image shown in FIG. 6. In this
example, bin 602a of the unwrapped borehole image may correspond to
the bottom-most left portion of the borehole image. Also, as shown
in FIG. 6, bin 602h may correspond to the top-most left portion of
the unwrapped image, bin 602i may correspond to the top-most right
portion of the image, and bin 602p may correspond to the
bottom-most right portion.
As bin 602a is the first bin in the sequence of bins of the
borehole image, the corresponding image data may be transmitted as
uncompressed data without any delta values calculated for the bin.
For each of the remaining bins 602b-602p, delta values may be
calculated for one or more parameter values based on the
corresponding values of the immediately preceding bin in the
sequence of bins. For example, the delta value calculations for
each of these remaining bins may be expressed by Equation (2) as
follows: .DELTA.A[n]=A[n]-A[n-1] (2), where A represents a downhole
parameter of interest, .DELTA.A is the change in value of parameter
A, n is the index to the current datum, and n-1 is the index to the
last datum transmitted.
FIG. 7 is a data plot 700 illustrating the delta values of
azimuthal bins 602a-602p of FIG. 6 relative to the location of each
azimuthal bin with respect to the borehole image, as described
above. In particular, data plot 700 shows that the change in delta
values between adjacent azimuthal bins is relatively small. Also,
the values obtained for the image tend to vary in a trend manner
from top-most bin to the bottom-most bin, with the values either
trending positive or negative from top to bottom (e.g., from bin
602h to bin 602a or from bin 602i to bin 602p).
In one or more embodiments, such trends may be taken into account
for purposes of adaptively encoding the borehole image data by
selecting an optimal delta encoding scheme based on the trend
characteristics of the data being encoded. The trend
characteristics of the data may depend on the particular
characteristics of the formation in which the data was collected.
For example, the variation trend in data values from top to bottom
of the borehole image as depicted in data plot 700 may be
indicative of formation property measurements collected by the
downhole tool while crossing a horizontal formation boundary as the
borehole is drilled at an angle or non-vertical direction within
the formation. In this example, the image data collected for a
portion of borehole circumference may be representative of one
formation layer while the data collected for the remainder of the
circumference is representative of a different formation layer.
In another example, the borehole may be drilled in a horizontal,
vertical or other direction through a horizontal layer of the
formation with generally homogenous formation characteristics. In
this case, there may be very little variation in the measured
formation properties at different points around the circumference
of the borehole.
In either of the above examples, the disclosed embodiments may be
used to select an optimal delta encoding scheme that accounts for
the particular characteristics of the formation as represented by
the data being encoded. The optimal delta encoding scheme may be
selected from a plurality of available delta encoding schemes, as
shown by the examples in FIGS. 8A, 8B, and 8C.
FIGS. 8A, 8B and 8C are diagrams of various delta encoding schemes
for generating a delta-encoded binned representation of the
measurements collected by the downhole tool for a section of the
borehole. Each of these delta encoding schemes may correspond to a
different pattern or sequence in which the delta values may be
calculated for the plurality of azimuthal bins around the
circumference of the borehole, as described above.
The delta encoding scheme or pattern shown in FIG. 8A is similar to
the encoding scheme described above with respect to FIG. 6, in
which the delta values are calculated for the plurality of bins in
a sequence starting from the bottom-most left bin (1) and
continuing in a clockwise direction around the borehole image to
the bottom-most right bin.
The delta encoding scheme of FIG. 8B may be used to calculate the
delta values for the bins in a single sequence that daisy-chains
from the bottom-most bin (1) to the top-most bin (16). For example,
referring back to the data shown in plot 700 of FIG. 7, as
described above, if the full datum for Bin 1 is sent followed by
Delta Bin 2, Delta Bin 3, Delta Bin 4, and so on, the data sequence
would be as follows: 0, <0, 0, <0, 0, etc. If such symmetry
exists, it may be possible to greatly reduce the number of bits
transmitted to the surface by, for example, transmitting three bits
to identify the pattern and then transmitting the first datum
without compression, followed by the unsigned value of the third
datum and each datum thereafter. However, it should be appreciated
that such symmetry may be unlikely in real-word applications and
the data collected downhole generally may not have the symmetry of
the data presented in this example.
The delta encoding scheme of FIG. 8C may be used to calculate the
delta values in two sequences--a first sequence from the
bottom-most left bin (1) to the top-most left bin (8) and a second
sequence from the bottom-most right bin (2B) to the top-most right
bin (9B). The delta encoding scheme of FIG. 8C may be the most
optimal scheme for encoding borehole image measurements collected
for a non-vertical section of the borehole. As described above with
respect to data plot 700 of FIG. 7, the delta values calculated for
such image data are known to vary in a trend manner relative to the
circumference of the borehole, e.g., from the top-most left
azimuthal bin to the bottom-most left bin or vice versa. For
example, such a data trend may allow the two sequences of delta
values calculated using this delta encoding scheme to have the same
sign. Accordingly, at least one of the sign bits for the two delta
value sequences may be eliminated from the delta encoded binary
representation of the image data.
In one or more embodiments, at least one of the delta encoding
schemes of FIGS. 8A-8C, as described above, may be selected based
on the symmetry of the borehole image data. For a borehole image
consisting of N data samples (S.sub.1, S.sub.2 . . . S.sub.N)
acquired by a downhole tool in a clockwise direction about the
borehole, the delta encoding scheme for transmitting the data to
the surface may be expressed as follows:
|S.sub.I-1+j-S.sub.N+I-j|.ident..DELTA..sub.I,j,j=1, . . . N/2
(where N is even); and
|S.sub.I-1+j-S.sub.N+I-j|.ident..DELTA..sub.I,j,j=1, . . .
(N-1)/2,I=1, . . . (N-1)N/2 (where N is odd).
However, it should be appreciated that embodiments of the present
disclosure are not limited thereto and that the data may be
acquired or sampled in any specified order as desired for a
particular implementation.
For a given expression "S.sub.k" representing the data in this
example, k may be interpreted cyclically, i.e., if a value of k
computes to N+1, S.sub.1 may be used; however, if a value of k
computes to zero or a negative value, the value of N may be added
to k.
For a set of data samples from a starting index I to an ending
index j, where the sum of the deltas from I to j is determined to
be less than a maximum allowable value (i.e.,
.SIGMA..sub.j.DELTA..sub.I,j<.DELTA.max), the full value of the
first data sample (S.sub.I) may be transmitted first, and the
remaining data samples may be treated as though they are
symmetric.
If the value of N is even, the remaining data samples may be
transmitted using the following sequence:
.times..times. ##EQU00001## .times. ##EQU00001.2##
In one or more embodiments, additional sequences may be calculated
as alternatives to the above sequence, and the sequence having the
least sign reversals may be selected for transmission to the
surface. For example, two alternate sequences may be defined as
follows:
Alternate sequence 1:
.times..times. ##EQU00002## .times. ##EQU00002.2## Alternate
sequence 2:
.times..times. ##EQU00003## .times. ##EQU00003.2##
For sufficiently small values of N, there may be repetitions in the
series of data samples for either of the above sequences as the
second portion of each series is filled according to the prescribed
sequence. To avoid using such repetitious values, another way of
defining the sequences may be as shown below for a default sequence
and the two alternate sequences:
Default Sequence:
.times..times. ##EQU00004##
.times..times..times..times..times..times..times..times..times..times..ti-
mes..times..times..times. ##EQU00004.2## ##EQU00004.3## Alternate
sequence 1:
.times..times. ##EQU00005##
.times..times..times..times..times..times..times..times..times..times..ti-
mes..times..times. ##EQU00005.2## ##EQU00005.3## Alternate sequence
2:
.times..times. ##EQU00006##
.times..times..times..times..times..times..times..times..times..times..ti-
mes..times..times. ##EQU00006.2## ##EQU00006.3##
If the value of N is odd, the remaining data samples may be
transmitted using the following sequence:
.times..times..times. ##EQU00007##
Thus, for example, if N=8 and I=3, the transmission sequence for
the data samples may be either of the two sequences shown in Table
1 below, where the transmission sequence in either of the last two
columns may be used as a possible alternative to the default
transmission sequence in the second column.
TABLE-US-00001 TABLE 1 Delta Encoding Sequences for N = 8 and I = 3
Bin Default Sequence Alternate Sequence 1 Alternate Sequence 2 1 S3
S3 S3 2 S4-S3 S4-S3 S4-S3 3 S5-S4 S5-S4 S5-S4 4 S6-S5 S6-S5 S6-S5 5
S7-S6 S2-S3 S7-S6 6 S2-S3 S1-S2 S8-S7 7 S1-S2 S8-S1 S2-S3 8 S8-S1
S7-S8 S1-S2
The Bin numbers in Table 1 above may represent the corresponding
azimuthal bins for the delta encoded data in this example.
Another approach that may be used builds on the symmetry of the
data by averaging symmetric pairs and transmitting an average
starting value along with differences of sequential averages
thereafter. Using the example above, the encoded data may be
transmitted as shown in Table 2 below.
TABLE-US-00002 TABLE 2 Delta Encoding Sequence for Symmetrical Data
Bin Sequence 1 (S3 + S2)/2 2 (S4 + S1)/2 - (S3 + S2)/2 3 (S5 +
S8)/2 - (S4 + S1)/2 4 (S6 + S7)/2 - (S5 + S8)/2
In yet another approach, the borehole image to be transmitted as a
signal may be fitted to a sine wave with an amplitude and phase
offset. The phase offset may then be used to identify the point of
symmetry. That is, whichever sampling bin the phase falls into may
be used as the center of symmetry in one of the above-described
schemes. Using this approach, it may be possible to orient the bins
such that it is more likely that all of the changes (or delta
values) that are transmitted have the same sign.
The approach in this example may involve first constructing an
estimator of the signal, S.sub.i for a sample i and then, carrying
out a linear regression of S.sub.i to a simple phase-shifted sine
wave with a constant offset A and random noise .sub.i, which may be
assumed to average to 0. Such an estimator may be expressed using
Equation (3) as follows:
.function..pi..function..pi. ##EQU00008##
The sum of the squares of error (SSE) for the regression may be
calculated using Equation (4):
.ident..times..times..times..times..function..pi..times..function..pi.
##EQU00009##
In one or more embodiments, the regression coefficients A, B and C
may be determined using Equations (5), (6) and (7),
respectively:
.times..times..times..function..pi..times..times..function..pi.
##EQU00010##
After the coefficients are determined, the SSE may be calculated.
If the SSE is less than a pre-determined threshold (e.g., as set
based on a given error tolerance for the transmitted data), then a
symmetry point may be determined for the data using Equation
(8)-(10) as follows:
.function..alpha..beta..function..alpha..beta..function..alpha..times..be-
ta..function..beta..function..beta. ##EQU00011##
The data series that was subjected to the regression in this
example may be determined using Equations (11) and (12):
.times..beta..function..pi..times..beta..function..pi.
.times..function..pi..beta. ##EQU00012##
Noting that 0.ltoreq..beta.<2*.pi. an approximate point of
symmetry of the sequence S.sub.i can be located by selecting the
value of i between 1 and N such that
.times..times..pi..beta..pi. ##EQU00013## is minimal, where the
expression Modulus(A,B) is the remainder of A when divided by
B.
From the form of the function, the signal will be approximately
symmetric about this point. The techniques described above may be
used with the point of symmetry determined in this manner. In one
or more embodiments, the above-described techniques may be used to
send the regression coefficients themselves instead of the
data.
It should be appreciated that other types of analyses may be
performed using, for example, a regression to a doubly periodic
function of the sample bin number (or higher order) in a similar
fashion. As the order of the periodicity increases, the opportunity
to exploit symmetry to further compress the data increases (as in
the examples described above). It should also be appreciated that
Fourier analysis may be used in place of regression. However, for
purposes of the regression example described herein, it may be
assumed that only a phase offset is sought at a period of one cycle
per revolution, two cycles per revolution, etc., but not
simultaneously at multiple frequencies.
As described above, an optimal delta encoding scheme may be
selected from among the delta encoding schemes described above, and
as exemplified in FIGS. 8A-8C, based on the particular
characteristics of the data and/or the formation in which the data
was collected. In one or more embodiments, the optimal delta
encoding scheme may be determined based on an orientation of the
downhole tool with respect to the vertical direction when the data
was collected within the formation. As described above, the
relative direction or orientation of the downhole tool with respect
to the vertical direction may be determined based on measurements
acquired by one or more sensors incorporated within the downhole
tool or associated drilling assembly. For example, if the
orientation of the downhole tool indicates that the borehole is
being drilled in a non-vertical direction, it is likely that the
downhole tool will intersect formation boundaries that are not
orthogonal to the borehole. If, for example, a formation boundary
has been determined through prior knowledge to be a horizontal
layer of the formation, the delta encoding scheme of FIG. 8C may be
selected as the optimal scheme for encoding the image data
collected by the downhole tool. In one or more embodiments, prior
knowledge of the general trends within the formation may be
available from seismic records or logs from offset wells. However,
if it is not known that the boundaries will be horizontal, the more
generalized scheme of FIG. 8B, as described above, may be used so
as to take into account the non-horizontal aspect of the boundary.
It should be appreciated that such a generalized scheme may also be
applicable in cases where a vertical well intersects a
non-horizontal boundary.
In some implementations, the delta encoding scheme of FIG. 8C may
be selected as the optimal delta encoding scheme by default. For
example, if an initial attempt to encode image data using the delta
encoding scheme of FIG. 8C fails to properly encode the data,
subsequent attempts may be made to encode the data using the delta
encoding schemes of FIG. 8B, followed by the delta encoding scheme
of FIG. 8A. It should be appreciated that the order in which the
delta encoding schemes of FIGS. 8A-8C are selected for the first,
second, and third attempts to encode the data may be adjusted as
desired for a particular implementation.
The particular delta encoding scheme that is selected to encode the
borehole image data may be identified using a predetermined number
of reserved bits, e.g., one or two bits, in the encoded data
stream. Even with the addition of the reserved bit(s) in the data
stream or telemetry packet, the overall telemetry rate for
transmitting the data to the surface may still be improved due to
the additional reduction in the total size of the encoded data as a
result of using an optimal delta encoding scheme selected for the
particular data. For example, an optimal delta encoding scheme
selected for encoding a 16-bin image of the borehole may save 8 to
16 bits, thereby making the 1 or 2 identification bits for the
delta encoding scheme negligible by comparison.
FIG. 9 is a flow chart of an illustrative process 900 adaptively
encoding borehole image data according to an optimal delta encoding
scheme selected for the particular data being encoded. For
discussion purposes, process 900 will be described using drilling
system 100 of FIG. 1, as described above. However, process 900 is
not intended to be limited thereto. Also, for discussion purposes,
process 900 will be described using telemetry device 134 of FIGS. 1
and 2, as described above, but is not intended to be limited
thereto. The steps of process 900 may be performed by, for example,
telemetry device 134 of FIGS. 1 and 2, as described above.
As shown in FIG. 9, process 900 begins in step 902, which includes
obtaining measurements collected by a downhole tool (e.g., tool
132a or 132b of FIG. 1, as described above) for a section of a
borehole at a current or other predetermined depth of the downhole
tool. As described above, the measurements collected by the
downhole tool may be used to obtain an image of the borehole
section with respect to one or more formation characteristics at
the current depth of the downhole tool. In step 904, the
measurements obtained in step 902 are assigned to a plurality of
azimuthal bins around the section of the borehole.
In step 906, a relative direction or orientation of the downhole
tool with respect to the vertical direction is determined as the
borehole is drilled within the formation. As described above, the
downhole tool may include one or more positional sensors for
tracking the azimuthal position of the tool within the borehole in
addition to its relative orientation with respect to the vertical
within the formation in which the borehole is being drilled.
In step 908, an optimal delta encoding scheme may be selected for
the measurements to be encoded, based on the tool's orientation
determined in step 906. In step 910, the measurements assigned to
the azimuthal bins are encoded according to the delta encoding
scheme selected in step 908. The delta encoded measurements may
then be transmitted in step 912 to a data processing device located
at the surface of the borehole.
FIG. 10 is a block diagram of an exemplary computer system 1000 in
which embodiments of the present disclosure may be implemented. For
example, computer system 144 of FIG. 1, as described above, may be
implemented using system 1000. Also, the steps of method 900 of
FIG. 9, as described above, may be implemented using system 1000.
System 1000 can be a computer or any other type of electronic
device. Such an electronic device includes various types of
computer readable media and interfaces for various other types of
computer readable media. As shown in FIG. 10, system 1000 includes
a permanent storage device 1002, a system memory 1004, an output
device interface 1006, a system communications bus 1008, a
read-only memory (ROM) 1010, processing unit(s) 1012, an input
device interface 1014, and a network interface 1016.
Bus 1008 collectively represents all system, peripheral, and
chipset buses that communicatively connect the numerous internal
devices of system 1000. For instance, bus 1008 communicatively
connects processing unit(s) 1012 with ROM 1010, system memory 1004,
and permanent storage device 1002.
From these various memory units, processing unit(s) 1012 retrieves
instructions to execute and data to process in order to execute the
processes of the subject disclosure. The processing unit(s) can be
a single processor or a multi-core processor in different
implementations.
ROM 1010 stores static data and instructions that are needed by
processing unit(s) 1012 and other modules of system 1000. Permanent
storage device 1002, on the other hand, is a read-and-write memory
device. This device is a non-volatile memory unit that stores
instructions and data even when system 1000 is off. Some
implementations of the subject disclosure use a mass-storage
storage device (such as a magnetic or optical disk and its
corresponding disk drive) as permanent storage device 1002.
Other implementations use a removable storage device (such as a
floppy disk, flash drive, and its corresponding disk drive) as
permanent storage device 1002. Like permanent storage device 1002,
system memory 1004 is a read-and-write memory device. However,
unlike storage device 1002, system memory 1004 is a volatile
read-and-write memory, such a random access memory. System memory
1004 stores some of the instructions and data that the processor
needs at runtime. In some implementations, the processes of the
subject disclosure are stored in system memory 1004, permanent
storage device 1002, and/or ROM 1010. For example, the various
memory units include instructions for implementing the disclosed
data encoding and associated decoding techniques. From these
various memory units, processing unit(s) 1012 retrieves
instructions and data to execute and process in order to execute
the processes of some implementations.
Bus 1008 also connects to input and output device interfaces 1014
and 1006. Input device interface 1014 enables the user to
communicate information and select commands to the system 1000.
Input devices used with input device interface 1014 include, for
example, alphanumeric, QWERTY, or T9 keyboards, microphones, and
pointing devices (also called "cursor control devices"). Output
device interfaces 1006 enables, for example, the display of images
generated by the system 1000. Output devices used with output
device interface 1006 include, for example, printers and display
devices, such as cathode ray tubes (CRT) or liquid crystal displays
(LCD). Some implementations include devices such as a touchscreen
that functions as both input and output devices. It should be
appreciated that embodiments of the present disclosure may be
implemented using a computer including any of various types of
input and output devices for enabling interaction with a user. Such
interaction may include feedback to or from the user in different
forms of sensory feedback including, but not limited to, visual
feedback, auditory feedback, or tactile feedback. Further, input
from the user can be received in any form including, but not
limited to, acoustic, speech, or tactile input. Additionally,
interaction with the user may include transmitting and receiving
different types of information, e.g., in the form of documents, to
and from the user via the above-described interfaces.
Also, as shown in FIG. 10, bus 1008 also couples system 1000 to a
public or private network (not shown) or combination of networks
through a network interface 1016. Such a network may include, for
example, a local area network ("LAN"), such as an Intranet, or a
wide area network ("WAN"), such as the Internet. Any or all
components of system 1000 can be used in conjunction with the
subject disclosure.
These functions described above can be implemented in digital
electronic circuitry, in computer software, firmware or hardware.
The techniques can be implemented using one or more computer
program products. Programmable processors and computers can be
included in or packaged as mobile devices. The processes and logic
flows can be performed by one or more programmable processors and
by one or more programmable logic circuitry. General and special
purpose computing devices and storage devices can be interconnected
through communication networks.
Some implementations include electronic components, such as
microprocessors, storage and memory that store computer program
instructions in a machine-readable or computer-readable medium
(alternatively referred to as computer-readable storage media,
machine-readable media, or machine-readable storage media). Some
examples of such computer-readable media include RAM, ROM,
read-only compact discs (CD-ROM), recordable compact discs (CD-R),
rewritable compact discs (CD-RW), read-only digital versatile discs
(e.g., DVD-ROM, dual-layer DVD-ROM), a variety of
recordable/rewritable DVDs (e.g., DVD-RAM, DVD-RW, DVD+RW, etc.),
flash memory (e.g., SD cards, mini-SD cards, micro-SD cards, etc.),
magnetic and/or solid state hard drives, read-only and recordable
Blu-Ray.RTM. discs, ultra density optical discs, any other optical
or magnetic media, and floppy disks. The computer-readable media
can store a computer program that is executable by at least one
processing unit and includes sets of instructions for performing
various operations. Examples of computer programs or computer code
include machine code, such as is produced by a compiler, and files
including higher-level code that are executed by a computer, an
electronic component, or a microprocessor using an interpreter.
While the above discussion primarily refers to microprocessor or
multi-core processors that execute software, some implementations
are performed by one or more integrated circuits, such as
application specific integrated circuits (ASICs) or field
programmable gate arrays (FPGAs). In some implementations, such
integrated circuits execute instructions that are stored on the
circuit itself. Accordingly, the steps of method 900 of FIG. 9, as
described above, may be implemented using system 1000 or any
computer system having processing circuitry or a computer program
product including instructions stored therein, which, when executed
by at least one processor, causes the processor to perform
functions relating to these methods.
As used in this specification and any claims of this application,
the terms "computer", "server", "processor", and "memory" all refer
to electronic or other technological devices. These terms exclude
people or groups of people. As used herein, the terms "computer
readable medium" and "computer readable media" refer generally to
tangible, physical, and non-transitory electronic storage mediums
that store information in a form that is readable by a
computer.
Embodiments of the subject matter described in this specification
can be implemented in a computing system that includes a back end
component, e.g., as a data server, or that includes a middleware
component, e.g., an application server, or that includes a front
end component, e.g., a client computer having a graphical user
interface or a Web browser through which a user can interact with
an implementation of the subject matter described in this
specification, or any combination of one or more such back end,
middleware, or front end components. The components of the system
can be interconnected by any form or medium of digital data
communication, e.g., a communication network. Examples of
communication networks include a local area network ("LAN") and a
wide area network ("WAN"), an inter-network (e.g., the Internet),
and peer-to-peer networks (e.g., ad hoc peer-to-peer networks).
The computing system can include clients and servers. A client and
server are generally remote from each other and typically interact
through a communication network. The relationship of client and
server arises by virtue of computer programs running on the
respective computers and having a client-server relationship to
each other. In some embodiments, a server transmits data (e.g., a
web page) to a client device (e.g., for purposes of displaying data
to and receiving user input from a user interacting with the client
device). Data generated at the client device (e.g., a result of the
user interaction) can be received from the client device at the
server.
It is understood that any specific order or hierarchy of steps in
the processes disclosed is an illustration of exemplary approaches.
Based upon design preferences, it is understood that the specific
order or hierarchy of steps in the processes may be rearranged, or
that all illustrated steps be performed. Some of the steps may be
performed simultaneously. For example, in certain circumstances,
multitasking and parallel processing may be advantageous. Moreover,
the separation of various system components in the embodiments
described above should not be understood as requiring such
separation in all embodiments, and it should be understood that the
described program components and systems can generally be
integrated together in a single software product or packaged into
multiple software products.
Furthermore, the exemplary methodologies described herein may be
implemented by a system including processing circuitry or a
computer program product including instructions which, when
executed by at least one processor, causes the processor to perform
any of the methodology described herein.
As described above, embodiments of the present disclosure are
particularly useful for encoding downhole image data. A method for
encoding downhole image data is described, where the method
includes: obtaining, by a downhole computing device, measurements
collected by a downhole tool around a circumference of a borehole
drilled within a formation; assigning the acquired measurements to
a plurality of azimuthal bins, each azimuthal bin corresponding to
an angular sector around the circumference of the borehole in which
at least one of the measurements was collected by the downhole tool
at a predetermined depth within the formation; selecting at least
one of a plurality of delta encoding schemes for the measurements
assigned to the plurality of azimuthal bins to be encoded;
generating a delta-encoded binary representation of the
measurements assigned to the plurality of bins, based on the
selected delta encoding scheme; and transmitting the generated
delta-encoded binary representation from the downhole computing
device to a surface computing device located at the surface of the
borehole. In one or more embodiments, the method may include
determining a relative orientation of the downhole tool within the
formation at the predetermined depth and selecting at least one of
the plurality of delta encoding schemes, based on the relative
orientation of the downhole tool.
Likewise, a computer-readable storage medium is described, where
the computer-readable storage medium has instructions stored
therein, which when executed by a computer cause the computer to
perform a plurality of functions, including functions to: obtain
measurements collected by a downhole tool around a circumference of
a borehole drilled within a formation; assign the acquired
measurements to a plurality of azimuthal bins, each azimuthal bin
corresponding to an angular sector around the circumference of the
borehole in which at least one of the measurements was collected by
the downhole tool at a predetermined depth within the formation;
determine a relative orientation of the downhole tool within the
formation at the predetermined depth; select at least one of a
plurality of delta encoding schemes for the measurements assigned
to the plurality of azimuthal bins to be encoded, based on the
relative orientation of the downhole tool; generate a delta-encoded
binary representation of the measurements assigned to the plurality
of bins, based on the selected delta encoding scheme; and transmit
the generated delta-encoded binary representation from the downhole
computing device to a surface computing device located at the
surface of the borehole.
In one or more embodiments, the foregoing method or
computer-readable medium may include steps or instructions for
performing functions relating to any of the following elements,
either alone or in combination with each other: the downhole
computing device may be a data encoder integrated within a
telemetry device of a drill string disposed within the borehole;
the telemetry device and the downhole tool may be components of a
bottom hole assembly of the drill string; the orientation of the
downhole tool may be determined based on measurements obtained from
an angle sensor incorporated within the downhole tool; the angle
sensor may be an accelerometer or a magnetometer; the measurements
may be collected by the downhole tool at different points around
the circumference of the borehole; the measurements collected by
the downhole tool at each of the different points around the
circumference of the borehole may include a formation property
measurement and a corresponding azimuthal position of the downhole
tool around the circumference when the formation property
measurement was collected; the delta-encoded binary representation
of the measurements may be generated by encoding the measurements
based on a location of a symmetry point corresponding to at least
one of the plurality of azimuthal bins; and the at least one delta
encoding scheme may be selected from among the plurality of delta
encoding schemes based on a measure of symmetry of the measurements
around the circumference of the borehole.
Furthermore, a system for encoding downhole image data is
described. The system includes at least one processor and a memory
coupled to the processor, where the memory has instructions stored
therein, which when executed by the processor, cause the processor
to perform a plurality of functions, including functions to: obtain
measurements collected by a downhole tool around a circumference of
a borehole drilled within a formation; assign the acquired
measurements to a plurality of azimuthal bins, each azimuthal bin
corresponding to an angular sector around the circumference of the
borehole in which at least one of the measurements was collected by
the downhole tool at a predetermined depth within the formation;
select at least one of a plurality of delta encoding schemes for
the measurements assigned to the plurality of azimuthal bins to be
encoded; generate a delta-encoded binary representation of the
measurements assigned to the plurality of bins, based on the
selected delta encoding scheme; and transmit the generated
delta-encoded binary representation from the downhole computing
device to a surface computing device located at the surface of the
borehole.
In one or more embodiments, the foregoing system may include any of
the following elements, either alone or in combination with each
other: the telemetry device and the downhole tool may be components
of a bottom hole assembly of the drill string; the orientation of
the downhole tool may be determined based on measurements obtained
from an angle sensor incorporated within the downhole tool; the
angle sensor may be an accelerometer or a magnetometer; the
measurements may be collected by the downhole tool at different
points around the circumference of the borehole; the measurements
collected by the downhole tool at each of the different points
around the circumference of the borehole may include a formation
property measurement and a corresponding azimuthal position of the
downhole tool around the circumference when the formation property
measurement was collected; the delta-encoded binary representation
of the measurements may be generated by encoding the measurements
based on a location of a symmetry point corresponding to at least
one of the plurality of azimuthal bins; and/or the at least one
delta encoding scheme may be selected from among the plurality of
delta encoding schemes based on a measure of symmetry of the
measurements around the circumference of the borehole.
While specific details about the above embodiments have been
described, the above hardware and software descriptions are
intended merely as example embodiments and are not intended to
limit the structure or implementation of the disclosed embodiments.
For instance, although many other internal components of the system
1000 are not shown, those of ordinary skill in the art will
appreciate that such components and their interconnection are well
known.
In addition, certain aspects of the disclosed embodiments, as
outlined above, may be embodied in software that is executed using
one or more processing units/components. Program aspects of the
technology may be thought of as "products" or "articles of
manufacture" typically in the form of executable code and/or
associated data that is carried on or embodied in a type of machine
readable medium. Tangible non-transitory "storage" type media
include any or all of the memory or other storage for the
computers, processors or the like, or associated modules thereof,
such as various semiconductor memories, tape drives, disk drives,
optical or magnetic disks, and the like, which may provide storage
at any time for the software programming.
Additionally, the flowchart and block diagrams in the figures
illustrate the architecture, functionality, and operation of
possible implementations of systems, methods and computer program
products according to various embodiments of the present
disclosure. It should also be noted that, in some alternative
implementations, the functions noted in the block may occur out of
the order noted in the figures. For example, two blocks shown in
succession may, in fact, be executed substantially concurrently, or
the blocks may sometimes be executed in the reverse order,
depending upon the functionality involved. It will also be noted
that each block of the block diagrams and/or flowchart
illustration, and combinations of blocks in the block diagrams
and/or flowchart illustration, can be implemented by special
purpose hardware-based systems that perform the specified functions
or acts, or combinations of special purpose hardware and computer
instructions.
The above specific example embodiments are not intended to limit
the scope of the claims. The example embodiments may be modified by
including, excluding, or combining one or more features or
functions described in the disclosure.
As used herein, the singular forms "a", "an" and "the" are intended
to include the plural forms as well, unless the context clearly
indicates otherwise. It will be further understood that the terms
"comprise" and/or "comprising," when used in this specification
and/or the claims, specify the presence of stated features,
integers, steps, operations, elements, and/or components, but do
not preclude the presence or addition of one or more other
features, integers, steps, operations, elements, components, and/or
groups thereof. The corresponding structures, materials, acts, and
equivalents of all means or step plus function elements in the
claims below are intended to include any structure, material, or
act for performing the function in combination with other claimed
elements as specifically claimed. The description of the present
disclosure has been presented for purposes of illustration and
description, but is not intended to be exhaustive or limited to the
embodiments in the form disclosed. Many modifications and
variations will be apparent to those of ordinary skill in the art
without departing from the scope and spirit of the disclosure. The
illustrative embodiments described herein are provided to explain
the principles of the disclosure and the practical application
thereof, and to enable others of ordinary skill in the art to
understand that the disclosed embodiments may be modified as
desired for a particular implementation or use. The scope of the
claims is intended to broadly cover the disclosed embodiments and
any such modification.
* * * * *
References